Abstract: Pre-drill modelling of fracture pressure (FP) is an essential part of well planning, reserve estimation and evaluation of the potential for inducing seismicity as the result of fluid injection. Estimation of stress ratio or Poisson’s ratio values or compaction state with depth is required in frequently used FP models. A new method to estimate FP is proposed which is based on Leak Off (LOT) and pore fluid pressure (Pp) data from offset wells and vertical stress ( S v )–depth relationships. LOT/ S v ratios observed in intervals of offset wells that are normally pressured (hydrostatic) are used to define an expected FP/ S v ratio for hydrostatic Pp conditions for all depths. Typical FP/ S v ratios for hydrostatic conditions derived using LOT data range from 0.81 to 0.89. Observed LOT values associated with Pp greater than hydrostatic (overpressured) in offset wells are used to quantify the rate of increase in FP with increasing overpressure (OP). The expected FP for hydrostatic conditions is compared with observed LOT values from depths where the pore fluid is overpressured and a relationship of increased FP, relative to the expected FP for hydrostatic conditions (residual FP (FPr)) with increasing OP is defined. The FPr:OP ratio typically ranges from 0.24 to 0.43. Fracture pressure models developed by this procedure may be used to predict FP for wells in different water depths and with Pp conditions different from those in the offset wells. The use of the model is demonstrated in three case studies taken from different geological settings: the Scotian shelf (offshore Nova Scotia), offshore Central Gulf of Mexico and the chalk interval from the Central North Sea.

Abstract Shale dykes, diapirs and mud volcanoes are common in the onshore and offshore regions of Brunei Darussalam. Outcrop examples show that shale has intruded along both faults and tensile fractures. Conventional models of overpressure-induced brittle failure assume that pore pressure and total stresses are independent of one another. However, data worldwide and from Brunei show that changes in pore pressure are coupled with changes in total minimum horizontal stress. The pore pressure/stress-coupling ratio (Δσ h /ΔP p ) describes the rate of change of minimum horizontal stress magnitude with changing pore pressure. Minimum horizontal stress measurements for a major offshore field where undepleted pore pressures range from normal to highly overpressured show a pore pressure/stress-coupling ratio of 0.59. As a consequence of pore pressure/stress coupling, rocks can sustain a greater increase in pore pressure prior to failure than predicted by the prevailing values of pore pressure and stress. Pore pressure/stress-coupling may favour the formation of tensile fractures with increasing pore pressure rather than reactivation of pre-existing faults. Anthropogenically-induced tensile fracturing in offshore Brunei supports this hypothesis.

Abstract Overpressure is created by two main processes: (1) stress applied to a compressible rock and (2) fluid expansion. Both processes are most effective in fine-grained lithologies, such as mudrocks and chalks. Both processes involve ineffective fluid expulsion to create pressures in excess of hydraulic equilibrium, emphasizing the importance of permeability (a poorly known rock property in fine-grained sedimentary rocks) in controlling pore pressure in the subsurface. Overpressure generation and fluid expulsion can be modeled assuming Darcy flow though a pore matrix. The basin conditions favoring high-magnitude overpressure from stress are a high sedimentation (loading) rate and/or strong lateral compressive forces. A high sedimentation rate, as a means to create rapid increase in temperature, also favors high- magnitude overpressure from fluid expansion mechanisms. An alternative method to achieve a rapid increase in temperature is a thermal pulse associated with tectonic or magmatic processes. Magnitude of overpressure from applied stress is controlled by the rate of increase in stress, sediment and fluid compressibility, and the rate of fluid expulsion. Continuous deposition of fine-grained sedimentary rocks leads to onset of overpressure at the fluid retention depth (FRD), the point at which fluid expulsion is no longer fully effective. Overpressure magnitude in this setting commonly increases at approximately 12.0–12.6 MPa/km (0.95–1.0 psi/ft), that is, along a gradient subparallel with the lithostatic stress gradient, implying only minor fluid expulsion. The variable characteristic of each lithology creates differences in the magnitude of overpressure. Magnitude of overpressure from fluid expansion mechanisms is controlled by the rate of volume change, which can be shown to be slow for the burial rates and temperature gradients found in most basins. In addition the volume increase in all reactions except gas generation is small. Although gas generation has the capacity to create high-magnitude overpressure locally (up to tens of MPa), the magnitude is diluted where a large connected reservoir volume is involved. The process is therefore most likely effective only within gas-generative source rocks and in thin intraformational reservoirs where oil cracks to gas. Chemical processes involving fabric change, dissolution/reprecipitation, and solid to liquid transfer may also play a part in creating conditions favoring overpressure through fluid retention, but these lntro cannot be quantified with existing data. Finally, overpressure related to hydraulic head and hydrocarbon buoyancy effects should not be ignored, but the magnitude of overpressure can be easily assessed.

Abstract Normally pressured reservoirs have pore pressures which are the same as a continuous column of static water from the surface. Abnormal pressures occur where the pore pressures are significantly greater than normal (overpressure) or less than normal (underpressure). Overpressured sediments are found in the subsurface of both young basins from about 1.0 to 2.0 km downwards, and in older basins, in thick sections of fine-grained sediments. The main mechanisms considered responsible for most overpressure conditions can be grouped into three broad categories, based on the processes involved: (1) ineffective volume reduction due to imposed stress (vertical loading during burial, lateral tectonic processes) leading to disequilibrium compaction, (2) volume expansion, including porosity increases due to changes in the solid:liquid ratios of the rock, and (3) hydraulic head and hydrocarbon buoyancy. The principal mechanisms which result in large magnitude overpressure are disequilibrium compaction and fluid volume expansion during gas generation. Disequilibrium compaction results from rapid burial (high sedimentation rates) of low-permeability rocks such as shales, and is characterized on pressure vs. depth plots by a fluid retention depth where overpressure commences, and increases downwards along a gradient which can closely follow the lithostatic (overburden) gradient. Disequilibrium compaction is typical in basins with a high sedimentation rate, including Tertiary deltas and some intracratonic basins. In older basins, disequilibrium compaction generated earlier in the basin history may be preserved only in thick, fine-grained sequences, but lost by vertical/lateral leakage from rocks with relatively high permeabilities. Gas generation from secondary maturation reactions, and oil cracking in the deeper parts of sedimentary basins, can result in large fluid volume increases, although the magnitudes are uncertain. In addition, the effect of increased pressures on the reactions involved is unknown. We doubt that any of the other mechanisms involving volume change can contribute significant regional overpressure, except in very unusual conditions. Hydraulic head and hydrocarbon buoyancy are mechanisms whose contributions are generally small; however, they can be easily assessed and may be important when additive to other mechanisms. The effects of transference of overpressure generated elsewhere should always be considered, since the present pressure distribution will be strongly affected by the ability of fluids to move along lateral and vertical conduits. Naturally underpressured reservoirs (as opposed to underpressure during depletion) have not been as widely recognized, being restricted mainly to interior basins which have undergone uplift and temperature reduction. The likely principal causes are hydraulic discharge, rock dilation during erosional unroofing, and gas migration during uplift.